This invention relates to in situ recovery of shale oil, and more particularly, to techniques for minimizing any effect on gas flow resistance in an in situ retort caused by strata having a relatively lower kerogen content than the average kerogen content of formation within the retort site.
The presence of large deposits of oil shale in the Rocky Mountain region of the United States has given rise to extensive efforts to develop methods of recovering shale oil from kerogen in the oil shale deposits. It should be noted that the term "oil shale" as used in the industry is in fact a misnomer; it is neither shale, nor does it contain oil. It is a sedimentary formation comprising marlstone deposit with layers containing an organic polymer called "kerogen," which upon heating, decomposes to produce liquid and gaseous products. It is the formation containing kerogen that is called "oil shale" herein, and the liquid product is called "shale oil."
A number of methods have been proposed for processing the oil shale which involve either first mining the kerogen bearing shale and processing the shale on the surface, or processing the shale in situ. The latter approach is preferable from the standpoint of environmental impact since the treated shale remains in place, reducing the chance of surface contamination and the requirement for disposal of solid wastes.
The recovery of liquid and gaseous products from oil shale deposits has been described in several patents, such as U.S. Pat. Nos. 3,661,423; 4,043,595; 4,043,596; 4,043,597; and 4,043,598 which are incorporated herein by this reference. Such patents describe in situ recovery of liquid and gaseous materials from a subterranean formation containing oil shale by fragmenting such formation to form a stationary, fragmented permeable body or mass of formation particles containing oil shale within the formation, referred to herein as an in situ oil shale retort. Hot retorting gases are passed through the in situ oil shale retort to convert kerogen contained in the oil shale to liquid and gaseous products, thereby producing retorted oil shale.
According to a method disclosed in U.S. Pat. No. 4,043,595, for example, an in situ retort is formed by excavating formation from a columnar void bounded by unfragmented formation having a vertically extending free face, drilling blasting holes adjacent the columnar void and parallel to the free face, loading the blasting holes with explosive, and detonating the explosive. This expands the formation adjacent the columnar void toward the free face such that fragmented formation particles occupy the columnar void and the space in the in situ retort site originally occupied by the expanded shale prior to such explosive expansion. Similarly, U.S. Pat. No. 4,043,597 discloses a method of forming an in situ retort by forming horizontal voids within a retort site and blasting the formation adjacent such horizontal voids for forming a fragmented permeable mass of formation particles within the retort site.
Oil shale deposits occur in generally horizontal beds and within a given bed there are an extremely large number of generally horizontal deposition layers containing kerogen known as "varves." The kerogen content of the formation is typically nonuniformly dispersed throughout a given bed.
The average kerogen content of formation containing oil shale can be determined by a standard "Fischer assay" in which a core sample customarily weighing 100 grams and representing one foot of core is subjected to controlled laboratory analysis involving grinding the sample into small particles which are placed in a sealed vessel and subjected to heat at a known rate of temperature rise to measure the kerogen content of the core sample. Kerogen content is usually stated in units of "gallons per ton," referring to the number of gallons of shale oil recoverable from a ton of oil shale heated in the same manner as in the Fischer analysis.
The average kerogen content of formation containing oil shale varies over a broad range from essentially barren shale having no kerogen content up to a kerogen content of about 70 gallons per ton. Localized regions can have even higher kerogen contents, but these are not common. It is often considered uneconomical to retort formation containing oil shale having an average kerogen content of less than about 8 to 10 gallons per ton.
Formation containing oil shale which is suitable for in situ retorting can be hundreds of feet thick. Often there are strata of substantial thickness within such formation having significantly different kerogen contents than other strata in the same formation. Thus, for example, in one formation containing oil shale in Colorado that is a few hundred feet thick, the average kerogen content is in the order of about 17 gallons per ton. Within this formation there are strata 10 feet or so thick in which the kerogen content is in excess of 30 gallons per ton. In another portion of the same formation there is a stratum almost 30 feet thick having nearly zero kerogen content. Similar stratification of kerogen content occurs in many formations containing oil shale.
During the course of retorting an in situ oil shale retort, hot retorting gas flows downwardly through the fragmented mass of formation particles. The void fraction, which is the ratio of the volume of the voids or spaces between particles in the fragmented mass to the total volume of the fragmented permeable mass of particles in an in situ oil shale retort, influences the resistance of the fragmented mass to such gas flow. A fragmented mass with a high void fraction has low resistance to gas flow, while a fragmented mass with low void fraction has a high resistance to gas flow. Flow resistance of the fragmented mass is important inasmuch as retorting may be continued for an extensive period of time. For example, one experimental in situ retort about 80 feet high was retorted for over a period of 120 days. If there is a high resistance to gas flow, a relatively high pressure drop will occur along the length of the fragmented mass. As a result, the blowers or compressors used for inducing gas flow within the retort will operate at relatively high pressure (for example, 5 psig) which requires appreciably more energy for driving the compressor or blower than if the pressure drop is relatively low.
The total energy requirements can be relatively high because of the long time required for retorting. Higher pressure operation also can take a greater capital expenditure for blowers or compressors, and some gas leakage from the retort can occur, further reducing efficiency.
The pressure differential or pressure drop from the top to bottom for vertical movement of gas down through the fragmented mass in an in situ oil shale retort depends upon various parameters of the retort and retorting process such as lithostatic pressure, void fraction of the fragmented mass, particle size in the fragmented mass, the temperature pattern of the retorting and combustion zones, gas volumetric flow rates, grade of oil shale being retorted, rate of heating of the fragmented mass, gas composition, gas generation from mineral decomposition and the like.
It is also desirable in forming an in situ retort to keep the total void volume as low as possible because of the cost of mining to form a void into which formation containing oil shale is expanded. Further, when the void is formed in the retort site, removed formation either must be retorted by more cumbersome and polluting above ground techniques, or the shale oil is lost when the mined-out material is discarded. Thus, the operator of an in situ oil shale retort is faced with opposing economic considerations that must be balanced to optimize production and minimize costs. On one side is the cost and loss of total yield of the retort by mining out formation to create the same void volume for the fragmented mass and on the other side is the cost of energy and equipment for forcing the retorting gas through the fragmented mass.